1. Field of the Invention
The present invention relates to a combustion apparatus, and more particularly to a combustion apparatus for a gas turbine that utilizes swirling and cyclonic staged combustion to minimize the formation of NO.sub.x and CO.
2. Description of the Related Art
The conventional steam-injected gas turbine cycle is shown schematically in FIG. 1. In such a system, the ambient air is pressurized in a compressor, heated in a combustor by burning of fuel, and expanded in the turbine. The turbine drives an air compressor and an electrical generator. The heat in the turbine exhaust is utilized to raise the relatively low pressure steam in a heat recovery steam generator and the steam is subsequently injected into the combustor. Steam injection is known to increase the power output and efficiency of the turbine by increasing the mass flow through the turbine relative to the compressor while decreasing the power required to drive the compressor.
The steam injected gas turbine cycle has shown good performance in sizes ranging from 500 kw industrial applications to relatively large utility plants of about 50 Mw and higher. In many instances, the steam injected gas turbine cycle is preferable to a conventional combined gas turbine/steam turbine cycle because it has a capital cost that is up to 20% less than that of a comparable capacity combined cycle power plant. This savings in capital costs occurs because the steam injected gas turbine cycle does not require a separate steam turbine or an associated heat rejection system.
Most industrial applications (500 kw-5 Mw) require only a small fraction of the power generating capacity of the typical utility power plant. However, few industries can generate electricity as economically as utilities because they cannot take advantage of economies of scale and higher steam parameters. There are many industrial applications, however, where both heat and electricity can be generated (cogeneration) on site at higher overall efficiency than when power and heat are generated separately. The steam injected gas turbine cycle is generally preferred for these relatively small industrial applications. This is because the expansion efficiency of steam turbines decreases with decreasing power levels and steam parameters, while the expansion efficiency of gas turbines is less dependent on power level. The steam injected gas turbine cycle is also more attractive for these low power level applications because it does not include a separate steam turbine or associated heat injection system that result in significantly higher capital investment.
In the past several years, there has been a boom of relatively small scale (less than 5 Mw) cogeneration plants in populated areas such as California. Many of these plants utilize natural gas fired combustion with steam injection to augment power production. These relatively compact, modular units can provide electrical efficiencies near 40 percent and higher when burning natural gas. However, due to the proximity of highly populated areas, these industrial plants face some of the strictest emission standards in the world. Meeting these standards has become one of the greatest challenges to the present day gas turbine combustion technology.
Gas turbine emissions include NO.sub.x, CO and unburned hydrocarbons. Recently, gas turbine vendors have developed staged combustors in an attempt to limit NO.sub.x emissions. For example, U.S. Pat. No. 4,102,125 discloses a primary and secondary combustion chamber with gasification of the fuel occurring in the first chamber. However, this patent discloses a pre-mixing chamber, a first mixing chamber, and second mixing chamber disposed before the primary combustion chamber. The complicated structure of this combustor makes it difficult to manufacture and operate.
As disclosed in U.S. Pat. No. 4,214,435, another technique for reducing NO.sub.x emissions is injecting steam into the combustor. Adding steam to the combustion zone lowers the flame and gas temperature and suppresses NO.sub.x formation.
Although staged combustion and steam injection can yield a reduction in NO.sub.x emissions, even further reductions are required in certain areas. For example, in some areas of the United States, gas turbine cogeneration plants must meet emission standards as low as 9 ppm at 15 percent O.sub.2. In these areas where staged combustion and steam injection cannot meet pollution requirements, the only option available is utilization of a selective catalytic reduction unit downstream of the gas turbine. However, this selective catalytic reduction unit has limited application in the small capacity range because of its significant capital cost. Moreover, experience with selective catalytic reduction units in cogeneration plants employing gas turbines has been reported as less than favorable. Therefore, there is a need for an ultra-low NO.sub.x natural gas fired combustor for a steam injected gas turbine cycle that eliminates the need for a catalytic reduction unit.
In addition to being used in steam injected gas turbine cycles, gas turbines are utilized in combined cycle applications with a steam turbine. Topping combustors for a gas turbine in a combined cycle application are typically a multiple "can-type" arrangement utilizing air-cooled metallic liners. Due to geometric considerations, these topping combustors often lack the ability to provide a wide turndown range and to allow easy staging of air. Also, a significant steam injection rate reduces overall combined cycle efficiency. Thus, topping combustors used in combined cycle applications result in relatively high NO.sub.x emissions that often require a selective catalytic reduction unit. Therefore, there is a need for an ultra-low NO.sub.x topping combustor for a gas turbine used in a combined cycle.